Controlled descent caged ball bypass plunger

ABSTRACT

The present invention is related to a bypass plunger. The plunger includes a plurality of flow ports, a cage including a seat, a flow restriction member positioned within the cage, a choke passageway extending between the seat and a lower end of the plunger. The cage is located proximate the flow ports. The flow restriction member is movable between a seated position and an unseated position in response to formation contents flowed into the wellbore from a reservoir. The flow restriction member is the unseated position when the plunger descends down a wellbore and is the seated position when the plunger ascends in the wellbore. The flow ports, cage, and choke passageway are in fluid communication when the flow restriction member is in the unseated position. In the seated position, the flow restriction member is in physical contact with the seat. This configuration provides a bypass plunger with controlled descent.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation of and claims the benefit of U.S. Pat. No. 15/985,368, filed on May 21, 2018, which is a conversion application of and claims the benefit of U.S. Provisional Application No. 62/509,640, filed on May 22, 2017, the entirety of which is herein incorporated by reference.

FIELD OF INVENTION

This invention relates to a plunger for lifting liquids upwardly in a hydrocarbon well. The invention relates to a by-pass plunger. More particularly, the invention relates to controlled descent caged-ball bypass plunger and to methods for increasing the productivity of gas wells using said plunger.

BACKGROUND OF THE INVENTION

There are many different techniques for artificially lifting formation liquids from hydrocarbon wells. Reciprocating sucker rod pumps are the most commonly used because they are the most cost effective, all things considered, over a wide variety of applications. Other types of artificial lift include electrically driven downhole pumps, hydraulic pumps, rotating rod pumps, free pistons or plunger lifts and several varieties of gas lift. These alternate types of artificial lift are more cost effective than sucker rod pumps in the niches or applications where they have become popular. One of these alternative types of artificial lift is known as a plunger lift, which is basically a free piston that moves upwardly in the well to lift formation liquids to the ground surface. Typically, plunger lifts are used in gas wells that are loading up with formation liquids thereby reducing the amount of gas flow. A free piston should be understood to be a piston that is not attached to a reciprocating member, but rather relies on formation contents (e.g., fluids and fluid pressure, gas and gas pressure, or a combination thereof from a formation) to move the piston components. A plunger lift assembly and method for using such an assembly is disclosed in commonly assigned U.S. Pat. Nos. 6,467,541 and 6,719,060, which are incorporated herein by reference in their entirety.

Gas wells reach their economic limit for a variety of reasons. A common reason is that the gas production declines to a point where the formation liquids are not readily moved up the production string to the ground surface. Two phase upward flow in a well is a complicated affair and most engineering equations thought to predict flow are only rough estimates of what is actually occurring. One reason is the changing relation of the liquid and of the gas flowing upwardly in the well. At times of more-or-less constant flow, the liquid acts as an upwardly moving film on the inside of the production tubing string while the gas flows in a central path on the inside of the liquid film. The gas flows much faster than the liquid film. When the volume of gas flow slows down below some critical value, or stops, the liquid runs down the inside of the flow string and accumulates in the bottom of the well.

If sufficient liquid accumulates in the bottom of the well, the well is no longer able to flow because the pressure in the reservoir is not able to flow against the pressure exerted by the liquid column. In that situation, the well is said to have loaded up and died. Years ago, gas wells were plugged much quicker than today because it was not economical to artificially lift small quantities of liquid from a gas well. At relatively high gas prices, it is economical to keep old gas wells on production. It has gradually been realized that gas wells have a life cycle that includes an old age segment where a variety of techniques are used to remove liquids from the well and thereby prevent the well from loading up and dying. A rule of thumb is that wells producing enough gas to have an upward velocity in excess of 10′/second will stay unloaded. Wells where the upward velocity is less than 5′/second will typically load up and die.

Free pistons or plunger lifts are a common type of artificial pumping system to lift liquid from a well that produces a substantial quantity of gas. Conventional plunger lift systems comprise a piston that is dropped into the well by stopping upward flow in the well, as by closing the wing valve on the well head. The piston is often called a free piston because it is not attached to a sucker rod string or other mechanism to pull the piston to the surface. When the piston reaches the bottom of the well, it falls into the liquid in the bottom of the well and ultimately into contact with a bumper spring, normally seated in a collar or resting on a collar stop. The wing valve is opened and gas flowing into the well pushes the piston upwardly toward the ground surface, pushing liquid on top of the piston to the ground surface.

A major disadvantage of conventional plunger lifts is that the well must be shut in so the piston is able to fall to the bottom of the well. Because wells in need of artificial lifting are susceptible to being easily killed, stopping flow in the well has a number of serious effects. Most importantly, the liquid on the inside of the production string falls to the bottom of the well, or is pushed downwardly by the falling piston. This is the last thing that is desired because it is the reason that wells load up and die. In response to the desire to keep the well flowing when a plunger lift piston is dropped into the well, attempts have been made to provide valved bypasses through the piston which open and close at appropriate times. Such devices to date are quite intricate and these attempts have so far failed to gain wide acceptance.

Recent development of multi-part plungers which may be dropped into a well while formation contents are flowing upwardly in the well are shown in U.S. Pat. Nos. 6,209,637, 6,467,541, and 6,719,060. In a recent development, taught in co-assigned and currently pending patent application Ser. No. 14/472,044, a flow restriction member is releasably retained by a sleeve member such that the flow restriction member is not released from the sleeve member solely by the force of gravity. If the flow restriction member prematurely releases from the sleeve member, such as by a sudden decrease in fluid pressure (“lift”), the sleeve and flow restriction member will separately drop in the well until at some point they are reunited and begin the upward journey once again. In many instances, the separate free piston components are not reunited until they reach the bottom of the well at which time the process starts once again, thus losing valuable time and exposing the well to potential fluid pressures that may cause the well to stop flowing.

In some of the prior art devices utilizing such a separate free piston assembly, the components are latched together before beginning the lift portion of the process. Such latching presents problems that are overcome by the assembly described in patent application Ser. No. 14/472,044. Specifically, the latching requires that the flow restriction member be captured by a mechanical structure that hold the flow restriction member in place during the lift. Such latching can be conveniently implemented at the bottom of the well where other structure is available to prevent movement of the flow restriction member while it is being latched, but just the opposite is true if the joinder of the flow restriction member and the sleeve member are being joined at a location above the bottom of the well. In such instances, the latching mechanism can actually interfere with the seating of the flow restriction member in the sleeve member and may result in the unwanted loss of time in joining the free piston members. The latching structure also tends to be cumbersome to install and frequently wears out prior to the useful life of the free piston assembly being completed.

For certain applications, the use of heavier, one-piece bypass plungers is preferred such as, for example, when sand causes premature wear on other types of plungers (e.g. padded plungers), in more dense fluid wells, during clean-out of a well, during operation in minimum bottom hole pressure, during operation in either high or low Gas Liquid Ratios (GLR). The use of one-piece bypass plungers circumvents long shut-in times. Recent development of such one-piece plungers is shown in U.S. Pat. Nos. 7,438,125 and 9,068,443 as well as U.S. Publication No. 2015-0300136. There remains, however, a need in the field for a simpler design single piece bypass plunger with fewer components that can fail, a plunger with a controllable fall rate to reduce excessive descent speeds that can prematurely damage the plunger while still lifting a large volume of fluids per run.

The current invention pertains to a one-piece, caged-ball by-pass plunger that can have a controllable descent through a gas well.

SUMMARY OF THE INVENTION

The current invention provides an improved bypass plunger, the descent of which, down a hydrocarbon well, can be controlled by flow ports, a cage, a caged ball, and an internal choke passageway.

The current invention provides a controlled-descent, caged-ball bypass plunger having an upper end and a lower end. The upper end includes a fishing neck to facilitate fishing the plunger out of a well and a plurality of flow ports. Located proximate the plurality of flow ports is a cage for housing a ball. The cage also includes a ball seat situated on top of a choke passageway, wherein the choke passageway extends from the ball seat to the lower end of the plunger.

The current invention also provides a controlled-descent, by-pass plunger with a body having an upper end and a lower end; a cage having a ball seat, a ball contained within said cage, wherein said ball is movable between a seated position and an unseated position; a choke passageway extending between said ball seat and said lower end of said body; one or more flow ports on the upper end of the plunger extending through said body and in fluid communication with the choke passageway when said ball is in the unseated position.

The current invention also provides a method for lifting fluids out of a gas wellbore such that the method includes the steps of providing a caged-ball bypass plunger having a body with an upper end and a lower end; a cage housing a ball positioned within said body, a ball seat configured to fit the ball wherein the ball is movable between a seated position and an unseated position; and a choke passageway extending longitudinally through the body between the ball seat and the lower end of the body wherein the choke passageway is closed when the ball is in the seated position, controlling the rate of descent of the plunger through the gas well by selecting the size of the choke passageway, containing the ball within the cage in an unseated position thereby allowing gas flow through the choke passageway and out the plunger from the flow ports as the plunger descends in the wellbore, and lifting fluid above the plunger out of the wellbore with the ball in the seated position as the plunger ascends in the well.

In accordance with principles of the present invention, a one-piece, caged-ball bypass plunger is contemplated. The plunger may comprise a body having an upper end and a lower end, a plurality of flow ports on the upper end of the body that extend through the body, a cage including a seat, a flow restriction member positioned within the cage, and a choke passageway extending between the seat and the lower end of the body. The cage may be located proximate the plurality of flow ports and configured to be in fluid communication with the plurality of flow ports. The flow restriction member is movable between a seated position and an unseated position such that the flow restriction member is the unseated position when the plunger descends down a wellbore and is the seated position when the plunger ascends in the wellbore. In the seated position, the flow restriction member is in physical contact with the seat. The choke passageway is in fluid communication with the cage and the plurality of flow ports when the ball is unseated.

The number of the flow ports may be between 1 and 5. The flow ports may have a helical shape. The flow restriction member may be a ball.

The plunger may further comprise a fishing neck configured to facilitate retrieval of the plunger from the wellbore. The plunger may further comprise a plurality of exterior seal rings.

The body may include a first component and a second component. The first component may include the flow ports, the cage, and a fishing neck. The second component may include the lower end. The first component may include an opening to accommodate the second component. The second component may be configured to be inserted into the opening of the first component. The second components may further include a region having a plurality of threads, fasteners, or other mechanisms capable of affixing the second component to a corresponding structure in the opening of the first component.

The second components may further include a region having a plurality of threads, fasteners, or other mechanisms capable of affixing the second component to the first component.

The body may be coated with Nickel Boron or Electroless-Nickel. The lower end of the body may be configured to contact a bumper spring assembly.

The flow restriction member may be configured to be movable in response to formation contents flowing into the wellbore from a reservoir. The plunger is configured to descend in the wellbore without shutting in the wellbore.

In accordance with principles of the present invention, a method for lifting formation fluid out of a wellbore is contemplated. The method may comprise introducing the plunger of claim 1 into the wellbore with the lower end of the plunger entering the wellbore first, allowing the plunger to descent to a bumper spring assembly, and allowing the plunger to ascent in the wellbore in response to formation contents flowing into the wellbore from a reservoir thereby pushing formation liquid above the plunger upward to a ground surface. The plunger may descent at a speed determined by the size and number of the flow ports.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a perspective view of one embodiment of a controlled descent, caged-ball bypass plunger in accordance with the current invention, illustrating the upper and lower ends of the plunger, the flow ports and a ball caged inside the upper end below the fishing neck.

FIG. 2 is a cross-sectional view of the plunger shown in FIG. 1, illustrating the ball, ball cage, ball seat, and choke passageway.

FIG. 3 is a schematic view of a controlled descent, caged-ball bypass plunger in accordance with an embodiment of the current invention wherein the plunger body includes a fishing neck, a plurality of flow ports, and a plurality of exterior seal rings.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The current invention provides a controlled-descent, caged-ball bypass plunger having an upper end and a lower end. The upper end includes a fishing neck to facilitate fishing the plunger out of a well. Between the upper end and the lower end is a cage for housing a ball. The cage also includes a ball seat situated on top of a choke passageway, wherein the choke passageway extends from the ball seat to the lower end of the plunger. The caged ball and the seat are used to support a column of fluid above the plunger during ascent of the plunger up a wellbore, thereby removing the fluid column from the well and preventing the well from loading up and dying. The diameter of the choke passageway may be selected to control the descent speed of the plunger when falling through the well to a bumper spring positioned lower in the wellbore. The size and number of the flow ports may also be selected to control the descent speed.

Referring to FIG. 1, a one-piece, caged-ball bypass plunger 100 is illustrated. The plunger 100 comprises a cylindrical body 105 that has an upper end 110, a lower end 115, and a plurality of exterior seal rings 120. As previously indicated, the upper end 110 of the body 105 may comprise a fishing neck 125 to facilitate the retrieval of the plunger 100 from the wellbore when necessary. The fishing neck 125 allows an operator to retrieve the plunger 100 without relying on the formation contents (i.e., fluid, gas, or pressure) flowing into the wellbore from the reservoir. For example, an operator can fish out the plunger when the amount of formation contents is inadequate to transport the plunger to the ground surface, when the amount of the formation contents is sufficient to transport the plunger to the ground surface but the operator wishes to retrieve the plunger sooner or the plunger is stuck in the wellbore, or for other reasons. The fishing neck 125 includes structures allowing retrieval of the plunger by tools and is a component known in the art. The fishing neck 125 is adjacent to the cage 135. The cage 135 and the ball 140 are located between the fishing neck 125 and the seal rings 120. The cage 135 and ball 140 may also be arranged in other locations.

The upper end 110 of the body 105 also includes a plurality of flow ports 130. The size and the number of ports 130 can vary, and this variation is well understood by those of skill in the art so as to accommodate the flow of fluid or gas through the plunger 100 as the plunger 100 descends in the wellbore. The larger the port 130 or number of ports 130, the more fluid or gas can flow through the ports 130 without creating unnecessary pressure drop. It is contemplated that the number of ports 130 per plunger 100 can be 1 or up to 5 ports. As shown, the ports 130 take the shape of a helical groove, but other shapes and dimensions are also contemplated. For example, a port may be 0.375″ in diameter and may have a length of 0.91″, 1.17″, 1.47″, or 1.73″, etc. as appreciated by a person of skill in the art. The port size, number, and shape can be selected and assembled to a user's request. Depending on the well conditions, an operator can also choose between a variety of plungers with different port sizes. The operator can also choose between heavier or lighter plungers depending either on the length of the plunger body or on the material used so as to further optimize for a given well condition. Different materials used may include 4140 steel, stainless steel or titanium which is much lighter. The plungers may also be coated with Nickel Boron or Electroless-Nickel for increased corrosion-resistance and longevity. The preferred embodiments of the plunger 100 of the current invention can be designed for 2.0625″, 2,375″ and 2.875″ O.D. production tubing strings.

As shown in FIG. 2, the body 105 further comprises a cage (or chamber) 135, a ball 140 within the cage 135, a ball seat 145, and an internal flow/choke passageway 150 that runs from the ball seat 145 and to the lower end 115 of the body 105. In a preferred embodiment, the ball diameter is 1 inch. However, ball diameters in the range of ¾″ through 1¼″ are also in accordance with the current invention. Other ranges are also contemplated. The flow ports 130 at the upper end 110 of the plunger 100 extend all the way into the ball cage 135 and are in fluid communication with the cage 135. The flow ports 130 are in fluid communication with the cage 135 regardless whether the ball 140 is in the seated position or the unseated position. The internal diameter of the choke passageway 150 can be varied to control descent down a wellbore. The smaller the internal diameter of the choke passageway 150, the slower the descent. The larger the internal diameter of the choke passageway 150, the less restriction to flow and the faster the descent in the well. The choke passageway diameter can be 5 mm, 6 mm, 8 mm, 10 mm or as would be contemplated by one of skill in the art. In a preferred embodiment, the diameter of the choke passageway 150 is 0.315 (or 8 mm). The width or diameter 52 of the choke passageway 150 can be smaller than that of the cage 135 (FIG. 2, 154). The length of the choke passageway 150 can also be adjusted depending on the application.

The ball 140 is movable between a seated position and an unseated position. FIG. 2 shows the ball 140 in the unseated position. There can be numerous unseated positions in that the ball 140 is considered as in the unseated position when the ball 140 leaves the ball seat 145 or is not in physical contact with the ball seat 145. The ball 140 can move to any location or unseated position in the cage 135 when the ball 140 leaves the ball seat 145. The ball 140 is confined in the cage 135 and the cage 135 is defined by the upper end 110 and the ball seat 145. The ball 140 is prohibited from escaping the cage 135 or the plunger 100. This configuration allows deploying only one piece of plunger into the wellbore to remove formation liquid and eliminates the need to separately introduce another plunger or ball. The body 105 and the ball 140 can be dropped into the wellbore simultaneously. The ball 140 is movable in the cage 135 in response to formation contents flowing into the wellbore from a reservoir. The ball 140 may be configured with a weight and size to determine an amount of fluid, gas, or pressure required to unseat the ball 140. The ball 140 is not mechanically latched to the cage 135, the upper end 110, or the lower end 115. In some embodiments, the cage 135 and the ball 140 may be configured in a manner such that the ball 140 can be unseated by a person holding the plunger 100 horizontally or by tilting the lower end 115 higher than the upper end 110 from the horizontal position.

The caged ball 140 and the seat 145 are used to lift a column of fluid above the plunger 100 during ascent up a wellbore. The plunger 100 is deployed into the wellbore with the lower end 115 entering the wellbore first. As the plunger 100 descends in a well bore, gas or liquid flowing into the wellbore from the reservoir passes through the choke passageway 150 and pushes the ball 140 upward from its seat 145 (unseated) thereby allowing the choke passageway 150 to fluidly communicate with the cage 135 and the ports 130 in the upper end 110 of the plunger 100. This allows the flowing gas and/or liquids to bypass the plunger 100 during descent so that the well does not need to be shut in while the plunger 100 falls to the bottom of the well. Because of this bypass feature, the well avoids lengthy shut-in periods thereby increasing the gas production of the well. Once the plunger 100 falls into the formation liquid in the bottom of the well and lands on the bumper spring assembly (with the lower end 115 contacting the assembly), the weight of the accumulated liquid above the plunger 100 (formation liquid above the upper end 110 as a result of falling into the formation liquid) will cause the caged ball 140 to sit on the ball seat 145 thereby closing the choke passageway 150. Pressure will build under the plunger 100 (under the lower end 115) until the pressure is sufficient to lift the closed plunger 100 and the column of liquid above it out of the well. Once the plunger 100 arrives at the ground surface and the fluid column is produced out of the well and down the surface flow line leading from the surface lubricator, the ball 140 is no longer held in the seated position and the plunger 100 can be dropped back into the flowing wellbore. Although FIG. 2 illustrates a ball, the ball can be other flow restriction member having other structure, shape, or size. The cage 135 can also have other structure, shape, or size to accommodate the flow restriction member.

FIG. 2 also shows that the body 105 comprises a first component (upper component) and a second component (lower component). The first component may include the upper end 110 (which includes the fishing neck 125, flow ports 130, and the cage 135) and the external seal rings 120. The second component may include the lower end 115. In some embodiments, the rings 120 can be part of the lower component. For ease of manufacture and/or installation of the ball into the cage, the first component and the second component may be two separate pieces joined together. The first component, such as a sleeve, may include an opening 160 to accommodate the second component and the second component may be inserted into the opening 160. The choke passageway 150 may be located in the interior of the lower component and the ball seat 145 may be situated at one end of the choke passageway 150 or the second component. The other end of the second component (i.e., the lower end 115) is configured to contact bumper a spring assembly. The second component may include a region 155 to engage with the first component. The region 155 may include a plurality of threads, fasteners, or other mechanisms that can mechanically affix the two components together. The region 155 prevents separation of the first component and the second component. The first component may include a corresponding structure to engage with the region 155. In one embodiment, the two components can be screwed together and spot welded at region 155. In some embodiments, part of the choke passageway 150 may be in the first component and part of the choke passageway 150 may be in the second component. The entire choke passageway 150 can be formed when the first component and the second component are joined together via the region 155. In that situation, the ball seat 145 is also located in the first component since the portion of the choke passageway 150 in the first component is the structure that provides the ball seat 145. The second component may end at a tip of the region 155 into the first component. Other configurations are also contemplated.

Referring to FIG. 3, the body 105 of the plunger 100 includes a plurality of exterior rings 120 (also referred to as seal rings) and grooves 122 (between the rings 120) that provide a functional seal between the tubing and plunger and help create a sealing turbulent gas flow that prevents liquids being lifted by the plunger from falling past the plunger (or downward toward the spring assembly) during the ascent phase in the well.

During operation, the plunger ball 140 is either in the seated or unseated position. The ball 140 is in the unseated position when the plunger is travelling down the wellbore. When the ball 140 is in the seated position on the ball seat 145 on top of and closing off the choke passageway 150, the plunger 100 is capable of lifting liquids and travelling upwards in the well. When the plunger 100 falls down the wellbore, the ball 140 is unseated, and flowing wellbore gas and liquids can bypass through the plunger 100. Gas flowing in the well beneath the plunger (beneath the lower end 115) will flow through the choke passageway 150, the cage 135, the ports 130 (in that order) and toward the ground surface of the well as the plunger 100 falls until it hits a lower bumper assembly located near the bottom of the well. Gas from the formation flow into the wellbore beneath the plunger 100, until enough pressure is built that lifts the plunger 100 and any accumulated liquid above the plunger (above the upper end 110) upwards in the well. A small amount of gas also flow around the external seal rings of the plunger creating a turbulent sealing flow that prevents liquids above the plunger from falling between plunger body 105 and the well tubing as the plunger 100 ascends in the wellbore.

The invention herein also provides a method for lifting fluids out of a hydrocarbon wellbore that includes providing a controlled descent caged-ball bypass plunger having the characteristics described above and the features illustrated in FIGS. 1-3. The method would be understood from the above and the overall disclosure.

Although this invention has been disclosed and described in its preferred forms with a certain degree of particularity, it is understood that the present disclosure of the preferred forms is only by way of example and that numerous changes in the details of construction and operation and in the combination and arrangement of parts may be resorted to without departing from the spirit and scope of the invention as hereinafter claimed. Broader, narrower, or different combinations of the described features are contemplated, such that, for example features can be removed or added in a broadening or narrowing way. 

What is claimed is:
 1. A plunger comprising: a body having an upper end and a lower end; a plurality of flow ports on the upper end of the body, the flow ports extending through the body; a case including a seat, the cage being located proximate the plurality of flow ports and configured to be in fluid communication with the plurality of flow ports; a flow restriction member positioned within the case, wherein the flow restriction member is movable between a seated position and an unseated position such that the flow restriction member is in the unseated position when the plunger descends down a wellbore and is in the seated position when the plunger ascends in the wellbore, and wherein in the seated position the flow restriction member is in physical contact with the seat; and a choke passageway extending between the seat and the lower end of the body, wherein the choke passageway is in fluid communication with the cage and the plurality of flow ports when the ball is unseated.
 2. The plunger of claim 1, wherein the number of the flow ports is between 2 and
 5. 3. The plunger of claim 1, wherein the flow ports have a helical shape.
 4. The plunger of claim 1, wherein the flow restriction member is a ball.
 5. The plunger of claim 1, further comprising a fishing neck configured to facilitate retrieval of the plunger from the wellbore.
 6. The plunger of claim 1, further comprising a plurality of exterior seal rings.
 7. The plunger of claim 1, wherein the body includes a first component and a second component, the first component includes the flow ports, the cage, and a fishing neck, and the second component includes the lower end.
 8. The plunger of claim 7, wherein the first component includes an opening to accommodate the second component.
 9. The plunger of claim 8, wherein the second component is configured to be inserted into the opening of the first component.
 10. The plunger of claim 9, wherein the second component further includes a region having a plurality of threads, fasteners, or other mechanisms capable of affixing the second component to a corresponding structure in the opening of the first component.
 11. The plunger of claim 7, wherein the second component further includes a region having a plurality of threads, fasteners, or other mechanisms capable of affixing the second component to the first component.
 12. The plunger of claim 1, wherein the body is coated with Nickel Boron or Electroless-Nickel.
 13. The plunger of claim 1, wherein the lower end of the body is configured to contact a bumper spring assembly.
 14. The plunger of claim 1, wherein the flow restriction member is configured to be movable in response to formation contents flowing into the wellbore from a reservoir.
 15. A method for lifting formation fluid out of a wellbore, comprising: introducing the plunger of claim 1 into the wellbore with the lower end of the plunger entering the wellbore first; allowing the plunger to descend to a bumper spring assembly, wherein the plunger descents at a speed determined by the size and number of the flow ports; and allowing the plunger to ascend in the wellbore in response to formation contents flowing into the wellbore from a reservoir thereby pushing formation liquid above the plunger upward to a ground surface.
 16. A method for lifting formation fluid out of wellbore, comprising: introducing the plunger of claim 1 into the wellbore with the lower end of the plunger entering the wellbore first; allowing the plunger to descent to a bumper spring assembly, wherein the plunger descents at a speed determined by the size of the choke passageway; and allowing the plunger to ascent in the wellbore in response to formation contents flowing into the wellbore from a reservoir thereby pushing formation liquid above the plunger upward to a ground surface. 